Wellhead systems are used for the extraction of hydrocarbons from subterranean deposits. Wellhead systems include a wellhead and, optionally mounted thereto, various Christmas tree equipment (for example, casing and tubing head spools, mandrels, hangers, connectors, and fittings). The various connections, joints and unions needed to assemble the components of the wellhead system are usually either threaded or flanged. As will be elaborated below, threaded unions are typically used for low-pressure wells where the working pressure is less than 3000 pounds per square inch (PSI), whereas flanged unions are used in high-pressure wells where the working pressure is expected to exceed 3000 PSI.
Independent screwed wellheads are well known in the art. The American Petroleum Institute (API) classifies a wellhead as an “independent screwed wellhead” if it possesses the features set out in API Specification 6A entitled “Specification for Wellhead and Christmas Tree Equipment.” The independent screwed wellhead has independently secured heads for each tubular string supported in the well bore. The pressure within the casing is controlled by a blowout preventer (BOP) typically secured atop the wellhead. The head is said to be “independently” secured to a respective tubular string because it is not directly flanged or similarly affixed to the casing head. Independent screwed wellheads are widely used for production from low-pressure production zones because they are economical to construct and maintain. Independent screwed wellheads are typically utilized where working pressures are less than 3000 pounds per square inch (PSI). Further detail is found in U.S. Pat. No. 5,605,194 (Smith) entitled “Independent Screwed Wellhead with High Pressure Capability and Method” which provides an apt summary of the features, uses and limitations of independent screwed wellheads.
Flanged wellheads, as noted above, are employed where working pressures are expected to exceed 3000 PSI. Wellhead systems with flanged connections are frequently designed to withstand fluid pressures of 5000 or even 10,000 PSI. The downside of flanged wellheads (also known in the art as ranged wellheads) is that they are heavy, time-consuming to assemble, and expensive to construct and maintain. As noted in U.S. Pat. No. 5,605,194 (Smith), a 5000-PSI ranged wellhead may cost two to four times that of an independent screwed wellhead with a working pressure rating of 3000 PSI. While oil and gas companies prefer to employ independent screwed wellheads rather than flanged wellheads, the latter must be used for high-pressure applications. Oil and gas companies are thus faced with a tradeoff between pressure rating and cost.
U.S. Pat. No. 5,605,194 (Smith) discloses an apparatus and method for temporarily reinforcing a low-pressure independent screwed wellhead with a high-pressure casing nipple so as to give it a high-pressure capability. The casing nipple described by Smith permits high-pressure fracturing operations to be performed through an independent screwed wellhead. Fracturing operations may achieve fluid pressures in the neighborhood of 6000 PSI, which the casing nipple is able to withstand even though the wellhead is only rated for 3000 PSI.
One of the disadvantages of the Smith casing nipple and method of use is that the casing nipple must be installed prior to fracturing and then removed prior to inserting the tubing string. As persons skilled in the art will readily appreciate, the steps of installing and removing the casing nipple generally entail killing the well, resulting in uneconomical downtime for the rig and potentially reversing beneficial effects of the fracturing operation. It is thus highly desirable to provide an apparatus and method which overcomes these problems.
There therefore exists a need for a wellhead system which withstands elevated fluid pressures and permits the extraction of subterranean hydrocarbons at less cost for the wellhead equipment.